Management's Discussion and Analysis

TRANSALTA CORPORATION

First Quarter Report for 2019

This Management’s Discussion and Analysis (“MD&A”) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See the Forward-Looking Statements section of this MD&A for additional information.

This MD&A should be read in conjunction with the unaudited interim condensed consolidated financial statements of TransAlta Corporation as at and for the three months ended March 31, 2019 and 2018, and should also be read in conjunction with the audited annual consolidated financial statements and MD&A contained within our 2018 Annual Integrated Report. In this MD&A, unless the context otherwise requires, “we”, “our”, “us”, the “Corporation”, and “TransAlta” refers to TransAlta Corporation and its subsidiaries. Our unaudited interim condensed consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) International Accounting Standards (“IAS”) 34 InterimFinancial Reporting for Canadian publicly accountable enterprises as issued by the International Accounting Standards Board (“IASB”) and in effect at March 31, 2019. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated May 13, 2019. Additional information respecting TransAlta, including its Annual Information Form, is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov, and on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein.

Additional IFRS Measures and Non-IFRS Measures

An additional IFRS measure is a line item, heading, or subtotal that is relevant to an understanding of the financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the financial statements but is not presented elsewhere in the financial statements. We have included line items entitled gross margin and operating income in our Condensed Consolidated Statements of Earnings (Loss) for the three months ended March 31, 2019 and 2018. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

We evaluate our performance and the performance of our business segments using a variety of measures. Certain of the financial measures discussed in this MD&A are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. Comparable earnings before interest, tax, depreciation and amortization ("EBITDA"), funds from operations ("FFO"), free cash flow ("FCF"), total consolidated net debt, adjusted net debt and segmented cash flow generated by the business, all as defined below, are non-IFRS measures that are presented in this MD&A. See the Discussion of Consolidated Financial Results, Segmented Comparable Results, Key Financial Ratios and Capital Structure and Liquidity sections of this MD&A for additional information.

Forward-Looking Statements

This MD&A includes "forward-looking information" within the meaning of applicable Canadian securities laws, and "forward-looking statements" within the meaning of applicable United States securities laws, including the United States Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements").  All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances.  Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may", "will", "can"; "could", "would", "shall", "believe", "expect", "estimate", "anticipate", "intend", "plan", "forecast" "foresee", "potential", "enable", "continue" or other comparable terminology.  These statements are not guarantees of our future performance, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from that set out in or implied by the forward-looking statements.

In particular, this MD&A contains forward-looking statements including, but not limited to: our strategic focus, including as it pertains to our operating performance and transitioning to clean power generation; the $750 million investment by Brookfield, including the closing of the second tranche of $400 million of preferred shares, the use of proceeds, the expected benefits associated with the Brookfield investment; the share buy backs of up to $250 million; the timing of closing the investment in the Skookumchuck Wind Energy Facility; the duration of the mothballing of the Sundance Unit 3 and Sundance Unit 5; pit development work and planned power maintenance outages; cost estimates for the development of the US Wind Projects; the construction of the Pioneer Pipeline, including the timing and costs thereof; the Windrise wind project and the cost and commercial operation date thereof; WindCharger Project and this project will be the first utility-scale battery storage project in Alberta, the receipt of funds from the Emissions Reduction

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Alberta, the supply of lithium-ion batteries, the receipt of regulatory approvals and the construction and commercial operation dates, and expected cost; the expected benefits from Project Greenlight and embedding the program into the business and realization of new value; the expected return of capital to shareholders; that TransAlta and Brookfield will work together to complete TransAlta’s transition to clean energy, maximize the value of the Hydro Assets, and create long-term shareholder value; Brookfield’s increase in its share ownership to 9%; the Mangrove legal action; Canadian Federal regulatory developments, including carbon pricing, the “backstop” mechanism and clean fuel standard; Alberta regulatory changes, including the Technology Innovation and Emission Reduction regime; the exposure under the Alberta Utilities Commission line loss proceeding; the FMG claims; the dispute with the Balancing Pool; the section under “2019 Financial Outlook”, including the Comparable EBITDA, FCF, dividend levels, availability for our generating segments, market pricing and portfolio management strategy, fuel costs, energy marketing, liquidity and capital resources, growth expenditures, planned outages in 2019 and lost production, and source of capital for funding capital expenditures; and impact of accounting changes.        

The forward looking statements in this MD&A are based on TransAlta’s beliefs and assumptions based on information available at the time the assumptions were made, including assumptions pertaining to: the Company’s ability to successfully defend against any existing or potential legal actions or regulatory proceedings, including by Mangrove Partners; the closing of the second tranche of the Brookfield investment occurring and other risks to the Brookfield investment not materializing; no significant changes to regulatory, securities, credit or market environments; the anticipated Alberta capacity market framework in the future; our ownership of or relationship with TransAlta Renewables Inc. not materially changing; the Alberta hydro assets achieving their anticipated future value, cash flows and adjusted EBITDA; the anticipated benefits and financial results generated on the coal-to-gas conversions and the Corporation’s other strategies; the Corporation’s strategies and plans; no significant changes in applicable laws, including any tax or regulatory changes in the markets in which we operate; the anticipated structure and framework of an Alberta capacity market in the future; risks associated with the impact of the Brookfield investment on the Corporation’s stakeholders, including its shareholders, debtholders and other securityholders and credit ratings; assumptions referenced in our 2019 guidance, including: Alberta spot power price equal to $50 to $60 per megawatt hours ("MWh"); Alberta contracted power price equal to $50 to $55 per MWh; Mid-C spot power prices equal to US$20 to US$25 per MWh; Mid-C contracted power price of US$47 to US$53 per MWh; sustaining capital between $140 million and $165 million; no material decline in the dividends expected to be received from TransAlta Renewables Inc.; the expected life extension of the coal fleet and anticipated financial results generated on conversion; and assumptions relating to the completion of the strategic partnership with and investment by Brookfield and proposed share buy-backs.

The forward-looking statements contained in this MD&A are subject to a number of risks and uncertainties that may cause actual performance, events or results to differ materially from those contemplated by the forward-looking statements. Some of the factors that could cause such differences include: the failure of the second tranche of the Brookfield investment to close; the outcomes of existing or potential legal actions or regulatory proceedings not being as anticipated, including those pertaining to the Brookfield investment; changes in our relationships with Brookfield and its affiliated entities or our other shareholders; our Alberta hydro assets not achieving their anticipated value, cash flows or adjusted EBITDA; the Brookfield investment not resulting in the expected benefits for the Corporation and its shareholders; the inability to complete share buy-backs within the timeline or on the terms anticipated or at all; fluctuations in demand, market prices and the availability of fuel supplies required to generate electricity; changes in the current or anticipated legislative, regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; the failure of the conditions precedent to the second tranche of the investment to be satisfied; risks associated with the calculation of the hydro assets’ EBITDA, including non-financial measures included in that calculation; the anticipated benefits of the joint Brookfield/TransAlta hydro operating committee not materializing; the timing and value of Brookfield’s exchange of exchangeable securities and the amount of equity interest in the hydro assets resulting therefrom; changes in general economic conditions including interests rates; operational risks involving our facilities; unexpected increases in cost structure; failure to meet financial expectations; structural subordination of securities; and other risks and uncertainties contained in the Corporation’s Management Proxy Circular dated March 26, 2019 and its Annual Information Form and Management’s Discussion and Analysis for the year ended December 31, 2018, filed under the Company’s profile with the Canadian securities regulators on www.sedar.com and the U.S. Securities and Exchange Commission (“SEC”) on www.sec.gov.

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on them, which reflect the Corporation's expectations only as of the date hereof. The Corporation is providing the guidance and other forward looking information for the purpose of assisting shareholders and financial analysts in understanding our financial position and results of operations as at and for the periods ended on the dates presented, as well as our financial performance objectives, vision and strategic goals, and may not be appropriate for other purposes. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.

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Highlights

	3 months ended March 31,
	2019		2018
Revenues	648		588
Net earnings (loss) attributable to common shareholders	(65	)	65
Cash flow from operating activities	82		425
Comparable EBITDA(1,2,3)	221		393
FFO(1,3)	169		318
FCF(1,3)	95		238
Net earnings (loss) per share attributable to common shareholders, basic and diluted	(0.23	)	0.23
FFO per share(1)	0.59		1.10
FCF per share(1)	0.33		0.83
Dividends declared per common share	—		0.04
Dividends declared per preferred share(4)	—		0.26
As at	March 31, 2019		Dec. 31, 2018
Total assets	9,328		9,428
Total consolidated net debt(5)	3,191		3,141
Total long-term liabilities	4,537		4,421

(1)  These items are not defined under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Reconciliation of Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.

(2) During the first quarter of 2019, we revised our approach to reporting adjustments to arrive at comparable EBITDA, mainly to be more comparable with other companies in the industry. Comparable EBITDA is now adjusted to exclude the impact of unrealized mark-to-market gains or losses. Both the current and prior period amounts have been adjusted to reflect this change.

(3) Includes $157 million received from the Balancing Pool for the early termination of Sundance B and C PPAs in the first quarter of 2018.

(4)  Weighted average of the Series A, B, C, E, and G preferred share dividends declared. Dividends declared vary year over year due to timing of dividend declarations.

(5) Total consolidated net debt includes long-term debt including current portion, amounts due under credit facilities, tax equity, and lease obligations, net of available cash and the fair value of economic hedging instruments on debt. See the table in the Capital Structure and Liquidity section of this MD&A for more details on the composition of net debt.

Excluding the one time receipt of $157 million for the termination of the Sundance B and C Power Purchase Arrangements ("PPA") received during the first quarter of 2018, comparable EBITDA for the three months ended March 31, 2019 decreased $15 million compared to the same period in 2018. The reduction was primarily a result of the expiry of the Mississauga contract, lower revenues on the Poplar Creek contract in Canadian Gas and an unplanned outage in US Coal. The decrease was partially offset by higher market prices in Hydro, stronger performance in Energy Marketing and lower Corporate costs. Canadian Coal comparable EBITDA remained consistent with 2018, despite that in the first quarter of 2018 we operated four Sundance units under PPAs compared to operating two merchant units in 2019, as we benefited from strong merchant pricing.

Excluding the one time receipt of $157 million ($115 million after tax) for the termination of the Sundance B and C PPAs, net loss attributable to common shareholders during the first quarter of 2019 was $15 million higher due to lower comparable EBITDA, higher depreciation, and higher earnings attributable to non-controlling interests, partially offset by lower interest expense and lower income tax expense.

Year-to-date FCF, one of the Corporation's key financial metrics, after adjusting for the one time receipt for the termination of the Sundance B and C PPAs received in 2018, was $14 million higher than the same period in 2018.

• The Australian Gas, Wind and Solar, Hydro, Energy Marketing and Corporate segments generated cash flow consistent with or better than the same period last year.

• In Alberta, Canadian Coal, Hydro and our wind assets benefited from higher power prices. Average prices during the first quarter in Alberta increased to $69 per MWh from $35 per MWh, compared to the same period in 2018, mainly reflecting the impact of the extreme cold weather during February and March of 2019.

• Excluding the one time receipt for the termination of the Sundance B and C PPAs of $157 million received in 2018, Canadian Coal cash flow was $10 million lower in the first three months of 2019 compared to 2018, mainly due to higher sustaining capital spend.

• US Coal cash flow was significantly lower in the first quarter of 2019 due to an unplanned outage for one of the units during extreme market conditions driven by low temperatures and high natural gas prices in early March 2019.

Significant Events

Our strategic focus continues to be improving our operating performance and transitioning to clean power generation. The Corporation made the following progress throughout the period:

▪ On March 25, 2019, the Corporation announced a $750 million investment in exchangeable securities by Brookfield Renewable Partners or its affiliates (collectively “Brookfield”) that provides the financial flexibility to drive TransAlta's transition to 100% clean energy by 2025, recognizes the anticipated future value of TransAlta's Alberta hydro assets, and also accelerates the Company's plan to return capital to its shareholders. Brookfield brings its extensive hydro experience with the addition of two

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new Board directors and the creation of a hydro operating committee. On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for unsecured subordinated debentures.

▪ On April 12, 2019 TransAlta signed an agreement to purchase a 49 per cent interest in the 136.8 MW Skookumchuk Wind Energy Facility.

▪ On March 28, 2019, the Corporation closed its acquisition of the Antrim wind project following the receipt of required regulatory approvals.

▪ On March 8, 2019, the Alberta Electric System Operator ("AESO") approved the Corporation's decision to extend the mothballing of Sundance Unit 3 and 5 until Nov. 1, 2021.

▪ On March 4, 2019, TransAlta approved the WindCharger Battery Storage Project, an innovative 10 MW / 20 MWh energy storage project.

See the Significant and Subsequent Events section of this MD&A for further details.

Availability and Production

Availability for the three months ended March 31, 2019 was 89.4 per cent compared to 93.9 per cent for the same period in 2018. The decreases were mainly due to higher unplanned outages and derates at US Coal and an unplanned outage at Australian Gas.

Production for the three months ended March 31, 2019 was 8,125 gigawatt hours ("GWh") compared to 7,171 GWh for the same period in 2018. The higher production is primarily due to a strong price environment in the Pacific Northwest, which resulted in higher dispatching at US Coal. This was partially offset by lower production at Canadian Coal due to the mothballing of Sundance Units 3 and 5 on April 1, 2018.

Electricity Prices

The average spot electricity prices in Alberta for the three months ended March 31, 2019 increased significantly compared to 2018 primarily due to significantly below average temperatures in February and early March.

Power prices were substantially higher in the Pacific Northwest in the three months ended March 31, 2019, mainly due to stronger weather driven demand in February and March as well as regional daily natural gas prices that averaged approximately US$14/mmBtu in the quarter.

Discussion of Consolidated Financial Results

We evaluate our performance and the performance of our business segments using a variety of measures. Comparable figures are not defined under IFRS. Those discussed below, and elsewhere in this MD&A, are not defined under IFRS and, therefore, should not be considered in isolation or as an alternative to or to be more meaningful than net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS, when assessing our financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another company. Each business segment assumes responsibility for its operating results measured to comparable EBITDA and cash flows generated by the business. Gross margin is also a useful measure as it provides management and investors with a measurement of operating performance that is readily comparable from period to period.

Comparable EBITDA

EBITDA is a widely adopted valuation metric and an important metric for management that represents our core business profitability. Interest, taxes, and depreciation and amortization are not included, as differences in accounting treatments may distort our core business results. In addition, we reclassify certain transactions to facilitate the discussion on the performance of our business:

(i) Certain assets we own in Canada are fully contracted and recorded as finance leases under IFRS. We believe it is more appropriate to reflect the payments we receive under the contracts as a capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables. We depreciate these assets over their expected lives;

(ii) We also reclassify the depreciation on our mining equipment from fuel and purchased power to reflect the actual cash cost of our business in our comparable EBITDA;

(iii) In December 2016, we agreed to terminate our existing arrangement with the Independent Electricity System Operator (“IESO”) relating to our Mississauga cogeneration facility in Ontario and entered into a new Non-Utility Generator (“NUG”) Enhanced

M4TRANSALTA CORPORATION

Dispatch Contract (the “NUG Contract”) effective Jan. 1, 2017. Under the NUG Contract, we received fixed monthly payments until Dec. 31, 2018 with no delivery obligations. Under IFRS, for our reported results in 2016, as a result of the NUG Contract, we recognized a receivable of $207 million (discounted), a pre-tax gain of approximately $191 million net of costs to mothball the units, and accelerated depreciation of $46 million. In 2017 and 2018, on a comparable basis, we recorded the payments we received as revenues as a proxy for operating income, and depreciated the facility until Dec. 31, 2018;

(iv) On commissioning the South Hedland Power Station in Australia, we prepaid approximately $74 million of electricity transmission and distribution costs. Interest income is recorded on the prepaid funds. We reclassify this interest income as a reduction in the transmission and distribution costs expensed each period to reflect the net cost to the business; and

(v) During the first quarter of 2019, we revised our approach to reporting adjustments to arrive at comparable EBITDA, mainly to be more comparable with other companies in the industry. Comparable EBITDA is now adjusted to exclude the impact of unrealized mark-to-market gains or losses. Both the current and prior period amounts have been adjusted to reflect this change.

A reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA results is set out below:

	3 months ended March 31(1)
	2019		2018
Net earnings (loss) attributable to common shareholders (2)	(65	)	65
Net earnings attributable to non-controlling interests	35		28
Preferred share dividends	—		10
Net earnings (loss)	(30	)	103
Adjustments to reconcile net income to comparable EBITDA
Depreciation and amortization	145		130
Foreign exchange loss	1		2
Net interest expense	50		68
Income tax expense	17		37
Comparable reclassifications
Decrease in finance lease receivables	6		15
Mine depreciation included in fuel cost	29		31
Australian interest income	1		1
Unrealized gains (losses) from risk management activities	2		(23	)
Adjustments to earnings to arrive at comparable EBITDA
Impacts associated with Mississauga recontracting(3)	—		29
Comparable EBITDA	221		393
Comparable EBITDA - excluding the PPA settlement	221		236

(1) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

(2) Includes $157 million received from the Balancing Pool for the early termination of Sundance B and C PPAs in the first quarter of 2018.

(3) The Mississauga recontracting ended in 2018. The impact for the three months ended March 31, 2019 was a decrease to revenue of $29 million.

Excluding the one time receipt of $157 million for the termination of the Sundance B and C PPAs received during the first quarter of 2018, comparable EBITDA for the three months ended March 31, 2019 decreased $15 million compared to the same period in 2018. The reduction was primarily a result of the expiry of the Mississauga NUG Contract, lower revenues on the Poplar Creek contract in Canadian Gas and an unplanned outage in US Coal. The decrease was partially offset by higher market prices in Hydro, stronger performance in Energy Marketing and lower Corporate costs. Canadian Coal comparable EBITDA remained consistent with 2018 despite that in the first quarter of 2018 we operated four Sundance units under PPAs compared to operating two merchant units in 2019 as we benefited from strong merchant pricing.

Funds from Operations and Free Cash Flow

FFO is an important metric as it provides a proxy for cash generated from operating activities before changes in working capital, and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FCF is an important metric as it represents the amount of cash that is available to invest in growth initiatives, make scheduled principal repayments on debt, repay maturing debt, pay common share dividends, or repurchase common shares. Changes in working capital are excluded so FFO and FCF are not distorted by changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period.

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The table below reconciles our cash flow from operating activities to our FFO and FCF:

	3 months ended March 31,
	2019		2018
Cash flow from operating activities(1)	82		425
Change in non-cash operating working capital balances	80		(123	)
Cash flow from operations before changes in working capital	162		302
Adjustment:
Decrease in finance lease receivable	6		15
Other	1		1
FFO	169		318
Deduct:
Sustaining capital(2)	(25	)	(20	)
Productivity capital	(2	)	(4	)
Dividends paid on preferred shares(3)	(10	)	(10	)
Distributions paid to subsidiaries' non-controlling interests	(32	)	(41	)
Payments on lease obligations(2)	(5	)	(4	)
Other	—		(1	)
FCF	95		238
Weighted average number of common shares outstanding in the year	285		288
FFO per share	0.59		1.10
FCF per share	0.33		0.83

(1) Includes $157 million received from the Balancing Pool for the early termination of Sundance B and C PPAs in the first quarter of 2018.

(2) During the first quarter of 2019, we revised the way in which FFO and FCF are reconciled to reflect the payments related to lease obligations as a separate line and remove finance leases from sustaining capital. 2018 results have been revised to reflect these changes.

(3) Dividends paid on preferred shares for the three months ended March 31, 2019 have been adjusted to include the April 1, 2019 payment as this relates to dividends payable in the first quarter of 2019.

The table below bridges our comparable EBITDA to our FFO and FCF:

	3 months ended March 31,
	2019		2018
Comparable EBITDA(1)	221		393
Interest expense	(42	)	(53	)
Provisions	4		(3	)
Current income tax expense	(7	)	(9	)
Realized foreign exchange gain (loss)	(5	)	3
Decommissioning and restoration costs settled	(7	)	(7	)
Other cash and non-cash items	5		(6	)
FFO	169		318
Deduct:
Sustaining capital(2)	(25	)	(20	)
Productivity capital	(2	)	(4	)
Dividends paid on preferred shares(3)	(10	)	(10	)
Distributions paid to subsidiaries' non-controlling interests	(32	)	(41	)
Payments on lease obligations(2)	(5	)	(4	)
Other	—		(1	)
FCF	95		238

(1) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change. 2018 includes $157 million received from the Balancing Pool for the early termination of Sundance B and C PPAs.

(2) During the first quarter of 2019, we revised the way in which FFO and FCF are reconciled to reflect the payments related to lease obligations as a separate line and remove finance leases from sustaining capital. 2018 results have been revised to reflect these changes.

(3) Dividends paid on preferred shares for the three months ended March 31, 2019 have been adjusted to include the April 1, 2019 payment as this relates to dividends payable in the first quarter of 2019.

	3 months ended March 31,
Supplemental disclosure	2019	2018
FFO - excluding the PPA settlement	169	161
FCF - excluding the PPA settlement	95	81

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FFO was up $8 million over the first three months of 2018 (after adjusting for the 2018 one time receipt of $157 million for the termination of the Sundance B and C PPAs), mainly due to lower interest expense partially offset by lower Comparable EBITDA of $15 million. The increase in FCF in the first quarter of 2019 compared to the same period in 2018 was mainly due to higher FFO and lower distributions paid to subsidiaries' non-controlling interests.

Segmented Comparable Results

Segmented cash flows generated by the business, shown in the table below, measures the net cash generated by each of our segments after sustaining and productivity capital expenditures, reclamation costs, provisions, and non-cash mark-to-market gains or losses. This is the cash flow available to: pay our interest and cash taxes, make distributions to our non-controlling partners and dividends to our preferred shareholders, grow the business, pay down debt and return capital to our shareholders.

	3 months ended March 31,
	2019		2018
Segmented cash inflow (outflow)(1)
Canadian Coal(2)	41		208
US Coal	(12	)	18
Canadian Gas	24		60
Australian Gas	30		31
Wind and Solar	66		65
Hydro	24		16
Generation cash inflow	173		398
Energy Marketing	24		(18	)
Corporate	(11	)	(25	)
Total comparable cash inflow	186		355
Total comparable cash inflow - excluding PPA settlement	186		198

(1) Segmented cash flow is a non-IFRS measure. 

(2) Includes $157 million received from the Balancing Pool for the early termination of Sundance B and C PPAs in the first quarter of 2018.

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Canadian Coal

	3 months ended March 31,
	2019		2018
Availability (%)	91.3		90.5
Contract production (GWh)	2,062		3,300
Merchant production (GWh)	1,657		909
Total production (GWh)	3,719		4,209
Gross installed capacity (MW)(1)	3,231		3,231
Revenues(2)	235		268
Fuel, carbon costs, and purchased power(2)	146		165
Comparable gross margin	89		103
Operations, maintenance, and administration	33		47
Taxes, other than income taxes	3		3
Termination of Sundance B and C PPAs	—		(157	)
Net other operating income	(10	)	(11	)
Comparable EBITDA(2)	63		221
Deduct:
Sustaining capital:
Routine capital	3		4
Mine capital	5		2
Planned major maintenance	3		—
Total sustaining capital expenditures(3)	11		6
Productivity capital	2		1
Total sustaining and productivity capital expenditures	13		7
Provisions	1		(3	)
Payments on lease obligations(3)	4		3
Decommissioning and restoration costs settled	4		6
Canadian Coal cash flow	41		208

(1) Includes units temporarily mothballed (774 MW Sundance Units 3 and 5).

(2) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

(3) On implementation of IFRS 16 in 2019, we have removed the finance leases from sustaining capital and included all payments on lease obligations as a separate line in arriving at segmented cash flow.

	3 months ended March 31,
Supplemental disclosure	2019	2018
Comparable EBITDA - excluding the PPA settlement	63	64
Canadian Coal cash flow - excluding the PPA settlement	41	51

Availability for the first quarter improved compared to 2018, mainly due to lower unplanned outages and derates in 2019.

Production for the three months ended March 31, 2019 decreased 490 GWh compared to the same period in 2018. Lower total production was due to the mothballing of Sundance Units 3 and 5 in April of 2018 and lower PPA dispatching due to the end of the PPAs at Sundance on April 1, 2018. Lower contract production is partially offset by lower unplanned outages and derates and higher merchant production.

Revenue for the three months ended March 31, 2019 decreased by $33 million compared to the same period in 2018, mainly due to the termination of the Sundance B and C PPAs on March 31, 2018, which resulted in lower production, partially offset by higher market prices.

In the first quarter of 2019, revenue per MWh of production was slightly lower at approximately $63 per MWh compared with $64 per MWh in 2018. Revenues in 2018 included the Sundance B and C PPA revenue as well as the pass through revenues associated with carbon compliance costs, which are no longer recoverable on the Sundance units as the PPAs have been terminated.

Fuel, carbon compliance costs, and purchased power costs per MWh of production were consistent in 2019 compared to 2018.

During the first quarter we co-fired with natural gas at the merchant units, when economical. Co-firing lowers the carbon compliance costs as the GHG emissions are lower. In addition, fuel costs can be lower by co-firing, depending on the market price for natural gas. We expect the level of co-firing to increase with the completion of the Pioneer Pipeline in the second quarter of 2019.

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OM&A costs were $14 million lower in the three months ended March 31, 2019 compared to 2018 due to cost reductions achieved in line with fewer units operating. However, there are certain fixed and common costs that are required to maintain the remaining operational Sundance units.

Excluding the one time receipt of $157 million for the termination of the Sundance B and C PPAs in the first quarter of 2018, comparable EBITDA for the three months ended March 31, 2019 was consistent with that achieved under the PPAs in the same quarter of 2018, despite the end of the Sundance PPAs and mothballing of two units. This largely reflects the combined impact of higher prices and lower OM&A costs offsetting the loss of the ability to recover Sundance carbon compliance costs.

Sustaining and productivity capital expenditures increased $5 million for the first quarter compared to the same period in 2018, as capital increased due to pit development work and planned power plant maintenance outages in 2019. There were no planned maintenance outages on operated power plants in 2018.

US Coal

	3 months ended March 31,
	2019		2018
Availability (%)(1)	76.9		99.7
Contract sales (GWh)	820		821
Merchant sales (GWh)	2,174		749
Purchased power (GWh)	(969	)	(852	)
Total production (GWh)	2,025		718
Gross installed capacity (MW)	1,340		1,340
Revenues(2)	159		85
Fuel and purchased power	154		44
Comparable gross margin	5		41
Operations, maintenance, and administration	14		15
Taxes, other than income taxes	1		1
Comparable EBITDA(2)	(10	)	25
Deduct:
Sustaining capital:
Planned major maintenance	—		5
Total sustaining capital expenditures(3)	—		5
Payments on lease obligations(3)	—		1
Decommissioning and restoration costs settled	2		1
US Coal cash flow	(12	)	18

(1) Adjusted availability was the same as availability for the first quarter of 2019 and 2018.

(2) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

(3) On implementation of IFRS 16 in 2019, we have removed the finance leases from sustaining capital and included all payments on lease obligations as a separate line. The contractual arrangement that was accounted for as a finance lease in 2018 and prior periods is not considered a lease under IFRS 16. Accordingly, the costs are reflected in fuel and purchased power and there are no payments on lease obligations from Jan. 1, 2019.

Availability for the three months ended March 31, 2019 was down compared to 2018 due to higher unplanned outages and derates. In 2019, both Centralia Units remained in service for the entire first quarter due to higher prices in the Pacific Northwest, whereas in 2018, both Centralia Units were taken out of service in February as a result of seasonally lower prices in the Pacific Northwest. In 2018, we performed major maintenance on both units during that time. Availability was also lower in 2019 as Centralia Unit 1 operated with a derate due to blocked precipitator hoppers for this entire period.

Production was up 1,307 GWh during the first three months of 2019 compared to 2018, due mainly to higher merchant sales and the timing of dispatch optimization.

Comparable EBITDA was down by $35 million during the first quarter of 2019 compared to 2018. During an isolated and extreme pricing event in March, Centralia was unable to commit one of its units to physical production for day ahead supply due to an unplanned forced outage repair. As a result, the Corporation incurred cash losses of $25 million on its day ahead hedging position. This isolated and extreme pricing event was the result of cold weather and strong demand in the Pacific Northwest as well as from extremely high natural gas prices. The affected unit was able to return to service earlier than expected for delivery in the real time market, however, it was only able to recover a portion of the day ahead hedge losses due to real time prices settling significantly below the day ahead settlement price. The day ahead and subsequent real time prices are historically very similar. The event occurred within a 48 hour period. The remaining variance of $10 million is mainly related to the strong results in 2018 as we fulfilled our contracted volumes with low priced power purchases.

TRANSALTA CORPORATION M9

Sustaining and productivity capital expenditures for the three months ended March 31, 2019 decreased $5 million as there were no planned outages in 2019 due to strong market prices.

US Coal's cash flow declined by $30 million for the first quarter of 2019, compared to the same period in 2018, due mainly to lower Comparable EBITDA.

Canadian Gas

	3 months ended March 31,
	2019	2018
Availability (%)	99.5	98.7
Contract production (GWh)	437	414
Merchant production (GWh)	159	39
Total production (GWh)	596	453
Gross installed capacity (MW)	945	953
Revenues(1)	72	104
Fuel and purchased power	31	29
Comparable gross margin	41	75
Operations, maintenance, and administration	11	13
Taxes, other than income taxes	—	1
Comparable EBITDA(1)	30	61
Deduct:
Sustaining capital:
Routine capital	5	1
Planned major maintenance	1	1
Total sustaining capital expenditures	6	2
Productivity capital	—	1
Total sustaining and productivity capital expenditures	6	3
Provisions and other	—	(2	)
Canadian Gas cash flow	24	60

(1) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

Availability for the three months ended March 31, 2019 increased compared to the same period in 2018, primarily due to lower planned outages at Sarnia.

Production for the three months ended March 31, 2019 increased 143 GWh compared to the same period in 2018, mainly due to higher production at the Sarnia facility.

Comparable EBITDA for the three months ended March 31, 2019 decreased by $31 million compared to the same period in 2018, mainly due to the Mississauga contract ending Dec. 31, 2018 and lower scheduled payments from the Poplar Creek finance lease. In 2018, comparable EBITDA included $29 million of revenues from the Mississauga contract.

Sustaining and productivity capital for the three months ended March 31, 2019 increased $3 million due to the timing of capital spares purchases for Sarnia.

Cash flow at Canadian Gas decreased by $36 million in the first quarter of 2019 compared to 2018, due to lower comparable EBITDA and timing of capital spend.

TRANSALTA CORPORATION M10

Australian Gas

	3 months ended March 31,
	2019	2018
Availability (%)	81.3	91.7
Contract production (GWh)	466	440
Gross installed capacity (MW)	450	450
Revenues	41	41
Fuel and purchased power	1	1
Comparable gross margin	40	40
Operations, maintenance, and administration	10	9
Comparable EBITDA	30	31
Australian Gas cash flow	30	31

Availability for the three months ended March 31, 2019 decreased compared to the same period in 2018, primarily due to an unplanned outage at the South Hedland power station.

Production for the three months ended March 31, 2019 increased 26 GWh compared to the same period in 2018, mainly due to increased customer demand. Our contracts in Australia are capacity contracts, and our results are not directly impacted by increased electricity generation.

Comparable EBITDA for the three months ended March 31, 2019 was consistent with the same period in 2018, which was expected due to the nature of our contracts.

Wind and Solar

	3 months ended March 31,
	2019	2018
Availability (%)	95.0	94.5
Contract production (GWh)	757	749
Merchant production (GWh)	214	279
Total production (GWh)	971	1,028
Gross installed capacity (MW)	1,382	1,363
Revenues(1)	87	89
Fuel and purchased power	4	6
Comparable gross margin	83	83
Operations, maintenance, and administration	12	13
Taxes, other than income taxes	2	2
Comparable EBITDA(1)	69	68
Deduct:
Sustaining capital:
Planned major maintenance	2	3
Total sustaining and productivity capital expenditures	2	3
Decommissioning and restoration costs settled	1	—
Wind and Solar cash flow	66	65

(1) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

Availability was slightly better than 2018. Production for the three months ended March 31, 2019 decreased by 57 GWh compared to the same period in 2018, mainly due to lower wind resources in Western Canada and the United States, partially offset by higher wind resources in Eastern Canada.

Comparable EBITDA for the three months ended March 31, 2019 was consistent with the same period in 2018 as lower overall production was offset by favourable pricing in Alberta and reductions in operating and production-based costs.

Wind and Solar's cash flow was consistent in the first quarter of 2019, compared to the same period in 2018, due to consistent comparable EBITDA and capital expenditures.

TRANSALTA CORPORATION M11

Hydro

	3 months ended March 31,
	2019		2018
Production
Energy contracted
Alberta hydro PPA assets (GWh)(1)	318		282
Other hydro energy (GWh)(1)	27		36
Energy merchant
Other hydro energy (GWh)	3		5
Total energy production (GWh)	348		323
Ancillary services volumes (GWh)(2)	781		946
Gross installed capacity (MW)	926		926
Revenues
Alberta hydro PPA assets energy	29		10
Alberta hydro PPA assets ancillary services	29		15
Capacity payments received under Alberta hydro PPA(3)	14		14
Other revenue(4)	5		6
Total gross revenues	77		45
Net payment relating to Alberta hydro PPA	(40	)	(18	)
Revenues	37		27
Fuel and purchased power	1		1
Comparable gross margin	36		26
Operations, maintenance, and administration	8		8
Taxes, other than income taxes	1		1
Comparable EBITDA(5)	27		17
Deduct:
Sustaining capital:
Routine capital	1		—
Planned major maintenance	2		1
Total sustaining capital expenditures	3		1
Hydro cash flow	24		16

(1) Alberta hydro PPA assets include 13 hydro facilities on the Bow and North Saskatchewan river systems included under the PPA legislation. Other hydro facilities include our hydro facilities in BC, Ontario and the hydro facilities in Alberta not included in the legislated PPAs.

(2) Ancillary services as described in the AESO Consolidated Authoritative Document Glossary.

(3) Capacity payments include the annual capacity charge as described in the Power Purchase Arrangements Determination Regulation AR 175/2000, available from Alberta Queen's Printer.

(4) Other revenue includes revenues from our non-PPA hydro facilities, our transmission business and other contractual arrangements, including the flood mitigation agreement with the Alberta government and black start services.

(5) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change. However, there was no impact to Hydro's comparable EBITDA.

Production for the three months ended March 31, 2019 increased by 25 GWh compared to the same period in 2018, primarily due to favourable market prices in Alberta, partially offset by lower water resources in British Columbia.

Total gross revenues for the first quarter of 2019 increased by $32 million compared to 2018, due to favourable power and ancillary services pricing. After net payments relating to the Alberta hydro PPA, comparable EBITDA for the three months ended March 31, 2019 increased by $10 million compared to the same period in 2018.

Hydro's cash flow improved by $8 million for the first quarter of 2019, compared to the same period in 2018, due mainly to higher Comparable EBITDA, partially offset by capital expenditures.

TRANSALTA CORPORATION M12

Energy Marketing

	3 months ended March 31,
	2019		2018
Revenues and gross margin(1)	28		(2	)
Operations, maintenance, and administration	9		8
Comparable EBITDA(1)	19		(10	)
Deduct:
Provisions and other	(5	)	8
Energy Marketing cash flow	24		(18	)

(1) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

For the three months ended March 31, 2019, comparable EBITDA was $29 million higher compared to the same period in 2018 due to strong results from US Western markets.

Energy Marketing's cash flow improved by $42 million in the first quarter of 2019, compared to the same period in 2018, due mainly to higher comparable EBITDA.

In addition, Energy Marketing generated $18 million in unrealized mark-to-market gains in the three months ended March 31, 2019 (2018 - $19 million gains), which were not included in comparable EBITDA or cash flow above. The cash flow from these mark-to-market gains is expected to be realized in future periods.

Corporate

	3 months ended March 31,
	2019		2018
Operations, maintenance, and administration	(7	)	(20	)
Comparable EBITDA	(7	)	(20	)
Deduct:
Sustaining capital:
Routine capital	3		3
Total sustaining capital expenditures	3		3
Productivity capital	—		2
Total sustaining and productivity capital expenditures	3		5
Payments on lease obligations(1)	1		—
Corporate cash flow	(11	)	(25	)

(1) On implementation of IFRS 16 in 2019, we have included all interest and payments on lease obligations as a separate lines.

During the period, operation, maintenance, and administration costs decreased by $13 million, primarily due to a realized gain from the total return swap on our share-based payment plans. A portion of the settlement cost of our share-based payment plans is fixed by entering into total return swaps, which are cash settled every quarter. Excluding the impact of the realized gain on the total return swap, corporate costs were $1 million lower than the first quarter of 2018, mainly due to reduced spending on productivity capital, partially offset by higher costs on share-based payment grants and a prior year credit adjustment.

TRANSALTA CORPORATION M13

Key Financial Ratios

The methodologies and ratios used by rating agencies to assess our credit ratings are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies. We are focused on strengthening our financial position and flexibility and aim to meet all our target ranges.

FFO Before Interest to Adjusted Interest Coverage

For the twelve months ended	March 31, 2019	Dec. 31, 2018
FFO	778	927
Less: Early termination payment received on Sundance B and C PPAs	—	(157	)
Add: Interest on debt and lease obligations, net of interest income and capitalized interest	162	174
FFO before interest	940	944
Interest on debt and lease obligations, net of interest income	165	176
Add: 50 per cent of dividends paid on preferred shares(1)	20	20
Adjusted interest	185	196
FFO before interest to adjusted interest coverage (times)	5.1	4.8

(1) Dividends paid on preferred shares for the three months ended March 31, 2019 have been adjusted to include the April 1, 2019 payment as this relates to dividends payable in the first quarter of 2019.

While both periods are within our target range, the ratio improved at March 31, 2019 compared to Dec. 31, 2018, mainly due to lower adjusted interest. Our target for FFO before interest to adjusted interest coverage is four to five times.

Adjusted FFO to Adjusted Net Debt

As at	March 31, 2019		Dec. 31, 2018
FFO(1)	778		927
Less: Early termination payment received on Sundance B and C PPAs(1)	—		(157	)
Less: 50 per cent of dividends paid on preferred shares(1, 2)	(20	)	(20	)
Adjusted FFO	758		750
Period-end long-term debt(3)	3,308		3,267
Less: Cash and cash equivalents	(109	)	(89	)
Less: Principal portion of TransAlta OCP restricted cash	—		(27	)
Add: 50 per cent of issued preferred shares	471		471
Fair value asset of hedging instruments on debt(4)	(8	)	(10	)
Adjusted net debt	3,662		3,612
Adjusted FFO to adjusted net debt (%)	20.7		20.8

(1) Last 12 months.

(2) Dividends paid on preferred shares for the three months ended March 31, 2019 have been adjusted to include the April 1, 2019 payment as this relates to dividends payable in the first quarter of 2019.

(3) Includes lease obligations and tax equity financing.

(4) Included in risk management assets and/or liabilities on the condensed consolidated financial statements as at March 31, 2019 and Dec. 31, 2018.

Our adjusted FFO to adjusted net debt remained consistent with 2018. Our target range for adjusted FFO to adjusted net debt is 20 to 25 per cent.

TRANSALTA CORPORATION M14

Adjusted Net Debt to Comparable EBITDA

As at	March 31, 2019		Dec. 31, 2018
Period-end long-term debt(1)	3,308		3,267
Less: Cash and cash equivalents	(109	)	(89	)
Less: Principal portion of TransAlta OCP restricted cash	—		(27	)
Add: 50 per cent of issued preferred shares	471		471
Fair value asset of hedging instruments on debt(2)	(8	)	(10	)
Adjusted net debt	3,662		3,612
Comparable EBITDA(3, 4)	980		1,152
Less: Early termination payment received on Sundance B and C PPAs	—		(157	)
Adjusted comparable EBITDA(3)	980		995
Adjusted net debt to comparable EBITDA(3) (times)	3.7		3.6

(1) Includes lease obligations and tax equity financing.

(2) Included in risk management assets and/or liabilities on the condensed consolidated financial statements as at March 31, 2019 and Dec. 31, 2018.

(3) Last 12 months.

(4) During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

Our adjusted net debt to comparable EBITDA ratio remained consistent with 2018. Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times.

Strategic Growth and Corporate Transformation

Coal-to-Gas Conversions

We are planning the conversion of some or all of the units at Sundance and Keephills to gas-fired generation in the 2020 to 2022 time frame. During the first quarter of 2019, we issued Limited Notice to Proceed (“LNTP”) for the coal-to-gas conversion on Sundance Unit 6 and expect to issue Full Notice to Proceed (“FNTP”) for this unit during the second half of 2019. We are targeting to complete the conversion of Sundance Unit 6 by the second half of 2020. Through the remainder of 2019, we expect to issue LNTP and FNTP for a number of the other Sundance and Keephills units and expect to complete the conversion of these units in 2021 and 2022. The cost to convert each unit is expected to be approximately $30 to $35 million per unit. In 2019, we expect to incur approximately $35 million for increasing our ability to co-fire gas and for advancing our coal-to-gas conversions.    

In addition, we continue to evaluate the potential to repower one or more of the steam turbines at Sundance by installing one or more combustion turbines and heat recovery steam generators, thereby creating highly efficient combined cycle units. We expect to make the decision to proceed with this investment before the end of 2019. Repowering is expected to cost 40% lower than a new combined cycle facility while achieving a similar heat rate.

Acquisition of Two US Wind Projects

On Feb. 20, 2018, TransAlta Renewables announced that it had entered into an arrangement to acquire two wind construction-ready projects in the United States. Construction of the projects is underway. The wind development projects consist of: i) a 90 MW project located in Pennsylvania that has a 15-year PPA with Microsoft Corp. ("Big Level") and ii) a 29 MW project located in New Hampshire with two 20-year PPAs ("Antrim") (collectively, the "US Wind Projects"), with counterparties that have Standard & Poor's credit ratings of A+ or better.

On March 28, 2019, the closing conditions related to the acquisition of Antrim were finalized and the Corporation acquired the development project. Cost estimates for the US Wind Projects have been re-forecasted to $250 million, primarily due to weather related delays. TransAlta Renewables will fund these costs either by acquiring additional preferred shares issued by TA Power or by subscribing for interest-bearing notes issued by the project entity. The proceeds from the issuance of such preferred shares or notes will be used exclusively in connection with the acquisition and construction of the US Wind Projects. TransAlta Renewables expects to fund these acquisition and construction costs using its existing liquidity and tax equity. The foundation work has been completed and the tower erection is planned for the second quarter of 2019. Both Big Level and Antrim are expected to be fully operational during the second half of 2019. See the Significant and Subsequent Events section of this MD&A for further details.

Pioneer Gas Pipeline Partnership

On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer Pipeline. Tidewater is constructing and will operate the 120 km natural gas pipeline, which will have an initial throughput of 130 MMcf/d with the potential to expand to approximately 440 MMcf/d. The Pioneer Pipeline will allow TransAlta to increase the amount of natural gas it co-fires at its Sundance and Keephills coal-fired units, resulting in lower carbon emissions and costs. As well, the Pioneer Pipeline is expected to provide a significant amount of the gas required for the full conversion of the coal units to natural gas. The investment for TransAlta, including associated infrastructure, is estimated to be approximately $100 million. Construction of the pipeline commenced in November 2018, construction is tracking to plan and the pipeline is expected to be fully operational by the second quarter of 2019.

TRANSALTA CORPORATION M15

Windrise Wind Project

On Dec. 17, 2018, TransAlta's 207 MW Windrise wind project was selected by the AESO as one of the three selected projects in the third round of the Renewable Electricity Program. TransAlta and the AESO executed a Renewable Electricity Support Agreement with a 20-year term. The Windrise project is situated on 11,000 acres of land located in the county of Willow Creek, Alberta and is expected to cost approximately $270 million. The project is progressing through the permitting process and is on track to reach commercial operation during the second quarter of 2021.

WindCharger Project

During the first quarter of 2019, TransAlta approved the WindCharger Battery Storage Project ("WindCharger"), an innovative 10 MW / 20 MWh energy storage project. WindCharger is located in southern Alberta in the Municipal District of Pincher Creek next to TransAlta’s existing Summerview Wind Farm Substation. WindCharger will store energy produced by the nearby Summerview II Wind Farm and discharge into the Alberta Electricity Grid at times of high-peak demand. This project is expected to be the first utility-scale battery storage facility in Alberta and will be receiving co-funding support from Emissions Reduction Alberta. Both a Sale and Purchase Agreement as well as a Services Agreement were executed with Tesla who will supply newly developed and highly efficient lithium-ion battery technology. Regulatory applications, including a facilities application to the Alberta Utilities Commission, have been submitted with approvals expected in during the third quarter of 2019. Construction is anticipated to begin in March 2020 with a commercial operation date of June 2020. The total expected cost of the project to TransAlta is US$8 million.

Project Greenlight

Project Greenlight is a multi-year program to transform our business and the delivery of the Corporation’s strategy. Business units are focusing both on cash flow improvements and the way the Corporation is delivering sustainable value. Through this program we delivered on projects that improved performance by improving generation efficiency, improving heat rates, lowering fuel costs, reducing GHG emissions, reducing operating and maintenance costs, optimizing our capital spend, avoiding new costs, reducing overhead costs and financing costs, improving working capital, monetizing assets, streamlining processes and achieving efficiencies.

The success of this project has enabled financial flexibility for new investments and as we proceed with plans to embed the transformation process into the business, we expect to continue to realize new value through innovation and process improvements. 

Significant and Subsequent Events

Strategic Investment by Brookfield

On March 25, 2019, the Corporation announced it had entered into an investment agreement whereby Brookfield Renewable Partners or its affiliates (collectively “Brookfield”) will invest $750 million in the Corporation. This investment provides the financial flexibility to drive TransAlta's transition to 100% clean energy by 2025, recognizes the anticipated future value of TransAlta's Alberta hydro assets, and also accelerates the Corporation's plan to return capital to its shareholders.

Under the terms of the agreement, Brookfield agreed to invest $750 million in TransAlta through the purchase of exchangeable securities, which will be exchangeable by Brookfield into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the future Hydro Assets’ EBITDA.

On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for 7% unsecured subordinated debentures due May 1, 2039. The remaining $400 million will be invested in October 2020 in exchange for a new series of redeemable, retractable first preferred shares, subject to the satisfaction of certain conditions precedent.

In addition, subject to the exceptions in the investment agreement, Brookfield has committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than 9% at the conclusion of the prescribed share purchase period, provided that Brookfield is not obligated to purchase any common shares at a price per share in excess of $10 per share. TransAlta shareholders elected two experienced Brookfield directors, Harry Goldgut and Richard Legault, to our Board of Directors at the 2019 Annual and Special Meeting of shareholders. TransAlta and Brookfield intend to work together to complete TransAlta’s transition to clean energy, maximize the value of the Hydro Assets, and create long-term shareholder value.

TransAlta has also committed to returning up to $250 million of capital to shareholders through share repurchases within the next three years.

Upon entering into the investment agreement and as required in the terms of the agreement, the Corporation paid to Brookfield a $7.5 million structuring fee. A commitment fee of $15 million, was paid upon completion of the initial funding. The structuring fee has been recorded as a prepaid transaction cost.

TRANSALTA CORPORATION M16

Skookumchuck Wind Energy Facility

On April 12, 2019, TransAlta signed an agreement to purchase a 49 per cent interest in the Skookumchuck Wind Energy Facility, a 136.8 MW construction-ready wind facility located in Lewis and Thurston counties near Centralia in Washington state.  The project has a 20-year power purchase agreement with an investment grade counterparty. TransAlta will make its investment decision when the facility reaches its commercial operation date, which is expected to be in December 2019. Total consideration for the investment will represent 49 per cent of the total construction cost less capital contributions from tax equity investors.

Mothballing of Sundance Units

On March 8, 2019, the Corporation announced that the AESO granted an extension to the mothballing of the following Sundance units:

▪ Sundance Unit 3 will remain mothballed until Nov. 1, 2021, extended from April 1, 2020; and

▪ Sundance Unit 5 will remain mothballed until Nov. 1, 2021, extended from April 1, 2020.

The extensions were requested by TransAlta based on TransAlta’s assessment of market prices and market conditions. TransAlta has the ability to return either of the units back to full operation by providing three months’ notice to the AESO.

Acquisition of Two US Wind Projects

On Jan. 2, 2019, TransAlta Renewables funded $45 million (US$33 million) of construction costs for the US Wind Projects.

On March 28, 2019, the closing conditions related to the acquisition of Antrim were finalized and the Corporation acquired the development project for total cash consideration of $24 million and the settlement of the balance of the outstanding loan receivable of $41 million. As a result, we recognized $50 million for assets under construction in property, plant and equipment and $15 million in intangibles. The Corporation also paid the final holdback for the Big Level development project of $7 million (US$5 million) due on the closing of Antrim. Upon the closing of the purchase of Antrim, TransAlta Renewables funded an additional $70 million (US$52 million) by subscribing for an interest-bearing promissory note issued by the project entity.

Please refer to the Strategic Growth and Corporate Transformation section of this MD&A for updates on ongoing projects. Please refer to Note 4 of the audited annual 2018 consolidated financial statements within our 2018 Annual Integrated Report and Note 3 of our unaudited interim condensed consolidated financial statements as at and for the three months ended March 31, 2019 for significant events impacting prior year results.

TRANSALTA CORPORATION M17

Regulatory Updates

Refer to the Regional Regulation and Compliance discussion in our 2018 annual MD&A for further details that supplement the recent developments as discussed below:

Canadian Federal Government

Federal Carbon Pricing

On June 21, 2018, the Greenhouse Gas Pollution Pricing Act (GGPPA) was passed. Under this Act, the Canadian federal government implemented a national price on GHG emissions. The price began at $20 per tonne of carbon dioxide equivalent (CO2e) emitted in 2019 and will rise by $10 per year until reaching $50 per tonne in 2022.

On Jan. 1, 2019, the GGPPA’s “backstop” mechanisms came into effect for large emitters in jurisdictions that did not implement an independent carbon pricing program or where the existing program was not deemed equivalent to the federal system - Ontario, Manitoba, New Brunswick, Saskatchewan, Prince Edward Island, Yukon and Nunavut. The backstop mechanism has two components: a carbon levy for small emitters and regulation for large emitters called the Output Based Pricing Standard (OBPS). The carbon levy sets a carbon price per tonne of greenhouse gas emissions related to transportation fuels, heating fuels and other, small emission sources. The OBPS is an intensity-based standard where large emitters must meet an industry specific emission intensity performance standard per unit of production. If the facility's emission intensity is below or above the performance standard, the facility will generate carbon credits or carbon obligations equal to the difference between the industry’s emission intensity performance standard and the regulated facility’s emission intensity.

Clean Fuel Standard

In 2016, the Canadian federal government announced plans to consult on the development of a Clean Fuel Standard to reduce Canada’s greenhouse gas emissions through the increase use of lower carbon fuels, energy sources and technologies. The objective of the regulation is to achieve 30 million metric tonnes of annual reductions in GHG emissions by 2030. The Clean Fuels Standard will establish lifecycle carbon intensity requirements separately for liquid, gaseous and solid fuels that are used in transportation, industry and buildings. Under the proposed policy, coal combusted at facilities that are covered by coal-fired electricity regulations will be exempt from the regulation. Natural gas used for electricity production is currently expected to be included under the gaseous stream. Consultation on the gaseous stream, commenced in 2019 and will continue into 2020. Publication of the draft regulations for the gaseous stream will occur in late 2020 with final regulations expected in 2021. The gaseous stream is currently expected to come into force by 2023. TransAlta continues to be engaged in the consultation process.

Alberta

On Jan. 1, 2018, the Alberta government transitioned from the Specified Gas Emitters Regulation to the Carbon Competitiveness Incentive Regulation  (“CCIR”) . Under the CCIR, the regulatory compliance moved from a facility-specific compliance standard to a product or sectoral performance compliance standard.

On April 16, 2019, the United Conservative Party ("UCP") won the Alberta provincial election with a majority government. The UCP have committed to moving away from the CCIR to a new regulation called the Technology Innovation and Emissions Reduction ("TIER") regime, expected to take effect on Jan. 1, 2020.

Under TIER, large emitters that emit over 100,000 tCO₂e per year will be covered. Similar to CCIR, TIER is an intensity-based carbon standard where emission obligations are assessed on a tonnes of carbon per unit of production above the set intensity standard. Electricity sector covered entities will have to meet a “good-as-best-gas” sector intensity standard that should be similar to CCIR at 370 tCO2e/MWh. All other larger emitters will need to reduce emission by 10% from their 2016-18 average facility emission factor. Facilities with emissions above the set reduction requirements will need to comply with TIER by: 1) paying the Carbon Fund price of $20/tCO₂e, 2) making reductions at their facility, 3) remitting emission performance credits from other facilities, or 4) remitting emission offset credits. The Carbon Fund payments will be used to fund emission reduction technologies in Alberta.

In addition, the UCP has committed to undertake a 90 day review of whether a capacity market or the current energy-only market is better for consumers. The process for consultation is still unclear, however, a report is expected during the third quarter of 2019.

The Corporation is monitoring these developments and other potential UCP policy changes that may affect the electricity sector.

TRANSALTA CORPORATION M18

Capital Structure and Liquidity

Our capital structure consists of the following components as shown below:

	March 31, 2019				Dec. 31, 2018
As at	$		%		$		%
TransAlta Corporation
Recourse debt - CAD debentures	647		9		647		9
Recourse debt - US senior notes	930		13		943		13
Credit facilities	227		3		174		2
US tax equity financing	26		1		28		—
Other	11		—		11		—
Less: Cash and cash equivalents	(59	)	(1	)	(16	)	—
Less: Principal portion of TransAlta OCP restricted cash	—		—		(27	)	—
Less: fair value asset of economic hedging instruments on debt	(8	)	—		(10	)	—
Net recourse debt	1,774		25		1,750		24
Non-recourse debt	442		6		469		6
Lease obligations	62		1		63		1
Total consolidated net debt - TransAlta Corporation	2,278		32		2,282		31
TransAlta Renewables
Credit facility	183		3		165		2
Less: cash and cash equivalents	(50	)	(1	)	(73	)	(1	)
Net recourse debt	133		2		92		1
Non-recourse debt	764		11		767		11
Lease obligations	16		—		—		—
Total net debt - TransAlta Renewables	913		13		859		12
Total consolidated net debt	3,191		45		3,141		43
Non-controlling interests	1,140		16		1,137		16
Equity attributable to shareholders
Common shares	3,059		42		3,059		42
Preferred shares	942		13		942		13
Contributed surplus, deficit, and       accumulated other comprehensive income	(1,124	)	(16	)	(1,004	)	(14	)
Total capital	7,208		100		7,275		100

Overall, our total consolidated net debt increased by $50 million during the first three months of 2019 mainly due to increased drawings on the credit facilities and the recognition of additional lease obligations as required due to accounting changes (see the Accounting Changes section of this MD&A), partially offset by scheduled principal repayments on non-recourse debt. Between 2019 and 2021, we have approximately $645 million of debt maturing.

Our credit facilities provide us with significant liquidity. We have a total of $2.0 billion (Dec. 31, 2018 - $2.0 billion) of committed credit facilities, comprised of our $1.25 billion (Dec. 31, 2018 - $1.25 billion) committed syndicated bank credit facility, TransAlta Renewables’ committed syndicated bank credit facility of $0.5 billion (Dec. 31, 2018 - $0.5 billion) and our $0.2 billion (Dec. 31, 2018 - $0.2 billion) committed bilateral facilities. These facilities were renewed during the second quarter of 2018 and expire in 2022, 2022, and 2020 respectively. The $1.75 billion (Dec. 31, 2018 - $1.75 billion) committed syndicated bank facilities are the primary source for short-term liquidity after the cash flow generated from the Corporation's business.

In total, $0.9 billion (Dec. 31, 2018 - $0.9 billion) is not drawn. At March 31, 2019, the $1.1 billion (Dec. 31, 2018 - $1.1 billion) of credit utilized under these facilities was comprised of actual drawings of $410 million (Dec. 31, 2018 - $339 million) and letters of credit of $697 million (Dec. 31, 2018 - $720 million). The Corporation is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $0.9 billion available under the credit facilities, the Corporation also has $109 million of available cash and cash equivalents.

The Corporation's subsidiaries have issued non-recourse bonds of $1,205 million (Dec. 31, 2018 - $1,235 million) that are subject to customary financing conditions and covenants that may restrict our ability to access funds generated by the facilities’ operations. Upon

TRANSALTA CORPORATION M19

meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the first quarter. However, funds in these entities that have accumulated since the first quarter test will remain there until the next debt service coverage ratio can be calculated in the second quarter of 2019. At March 31, 2019, $70 million (Dec. 31, 2018 -$33 million) of cash was subject to these financial restrictions.

We have $31 million (Dec. 31, 2018 - $31 million) of restricted cash related to the Kent Hills project financing that is being held in a construction reserve account, which will be released upon certain conditions being met, which are expected to be finalized in Q2 2019. Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit. We have elected to use letters of credit as at March 31, 2019.

The weakening of the US dollar has decreased our long-term debt balances by $15 million in 2019. Almost all our US-denominated debt is hedged either through financial contracts or net investments in our US operations. During the period, these changes in our US-denominated debt were offset as follows:

	March 31, 2019
Effects of foreign exchange on carrying amounts of US operations (net investment hedge)	(8	)
Foreign currency economic cash flow hedges on debt	(2	)
Economic hedges on US operations	(4	)
Unhedged	(1	)
Total	(15	)

Share Capital

The following tables outline the common and preferred shares issued and outstanding:

As at	May 13, 2019	March 31, 2019	Dec. 31, 2018
	Number of shares(millions)
Common shares issued and outstanding, end of period	284.6	284.6	287.5
Preferred shares
Series A	10.2	10.2	10.2
Series B	1.8	1.8	1.8
Series C	11.0	11.0	11.0
Series E	9.0	9.0	9.0
Series G	6.6	6.6	6.6
Preferred shares issued and outstanding, end of period	38.6	38.6	38.6

Non-Controlling Interests

As of March 31, 2019, we own 60.8 per cent (March 31, 2018 - 64.0 per cent) of TransAlta Renewables. Our ownership percent decreased due to common shares issued under TransAlta Renewables Dividend Reinvestment Plan. We do not participate in this plan.

We also own 50.01 per cent of TransAlta Cogeneration L.P (“TA Cogen”), which owns, operates, or has an interest in four natural-gas-fired facilities (Mississauga, Ottawa, Windsor, and Fort Saskatchewan) and one coal-fired generating facility.

Reported earnings attributable to non-controlling interests for the first quarter 2019 increased to $35 million from $28 million in the same period of 2018. Earnings were up at TransAlta Renewables in 2019 due to a favourable change in the fair value of financial assets related to its investment in the Australian business, partially offset by lower interest income and higher foreign exchange losses. Earnings from TA Cogen LP were consistent quarter to quarter.

M20TRANSALTA CORPORATION

Returns to Providers of Capital

Net Interest Expense

The components of net interest expense are shown below:

	3 months ended March 31
	2019		2018
Interest on debt	41		53
Interest income	(2	)	(3	)
Capitalized interest	(1	)	—
Loss on early redemption of US Senior Notes and Debentures	—		5
Interest on lease obligations	1		1
Credit facility and bank charges	3		3
Other interest	2		3
Accretion of provisions	6		6
Net interest expense	50		68

Interest expense decreased during the three months ended March 31, 2019 due to lower debt levels and the $5 million pre-payment premium incurred in the first quarter of 2018 relating to the early redemption of the US$500 million Senior Notes.

Dividends to Shareholders

The following are the common and preferred shares dividends declared up to May 13, 2019:

			Common	Preferred Series dividends per share
	Payable date		dividends
Declaration date	Common Shares	Preferred Shares	per share	A	B	C	E	G
April 15, 2019	July 1, 2019	June 30, 2019	0.04	0.16931	0.23136	0.25169	0.32463	0.33125

TRANSALTA CORPORATION M21

Financial Position

The following table outlines significant changes in the Condensed Consolidated Statements of Financial Position from March 31, 2019, to Dec. 31, 2018:

	Increase/
Assets	(decrease)		Primary factors explaining change
Cash and cash equivalents	20		Timing of receipts and payments
Trade and other receivables	(25	)	Timing of customer receipts and seasonality of revenues.
Prepaid expenses	12		Annual property tax and insurance payments ($11 million)
Inventory	(16	)	Reduced coal inventory at Canadian Coal operations
Restricted cash	(35	)	Restricted cash related to the OCP bonds was used as part of the debt repayment
Property, plant, and equipment, net	(135	)	Depreciation for the period ($152 million), adjustments on implementing IFRS 16 ($62 million), unfavourable change in foreign exchange rates ($15 million), partially offset by additions ($34 million), acquisition relating to Antrim ($49 million) and revisions to decommissioning and restoration costs ($14 million)
Right of use assets, net	81		Transfers from property, plant and equipment, intangible assets and other assets ($38 million) and new right of use assets recognized under IFRS 16 ($47 million) (see Accounting Changes section for further details)
Risk management assets (current and long term)	(38	)	Market changes, contract settlements and unfavourable foreign exchange rates, partially offset by new contracts entered into during the period
Other assets	49		Note receivable for the project development costs related to the Pioneer Pipeline and and Brookfield structuring fee ($7.5 million)
Others	(13	)
Total decrease in assets	(100	)
	Increase/
Liabilities and equity	(decrease)		Primary factors explaining change
Accounts payable and accrued liabilities	(39	)	Timing of payments and accruals
Dividends payable	(11	)	Timing of the declaration of common share dividends
Credit facilities, long term debt, and lease obligations (including current portion)	41		Drawings on the credit facility ($71 million) and net increase in lease obligations on implementation of IFRS 16 ($15 million) were partially offset by favourable changes in foreign exchange ($15 million) and repayments of long-term debt ($29 million)
Contract liabilities	17		Contract liabilities moved from defined benefit obligation and other long term liabilities as they are no longer considered leases on the adoption of IFRS 16 (see the Accounting Changes section for further details)
Defined benefit obligation and other long term liabilities	8		Actuarial losses ($27 million) partially offset by liabilities moved to contract liabilities ($15 million)
Deferred income tax liabilities	(11	)	Decrease in taxable temporary differences
Risk management liabilities (current and long term)	11		Market changes, contract settlements and unfavourable foreign exchange rates, partially offset by new contracts entered into during the period
Equity attributable to shareholders	(120	)	Net loss ($65 million) and other comprehensive loss ($60 million)
Non-controlling interests	3		Net earnings ($35 million) and changes in non-controlling interests in TransAlta Renewables from dividend reinvestment plan ($6 million), partially offset by distributions paid and payable ($39 million)
Others	1
Total decrease in liabilities and equity	(100	)

M22TRANSALTA CORPORATION

Cash Flows

The following tables outline significant changes in the Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2019, compared to the three months ended March 31, 2018: 

3 months ended March 31,	2019		2018		Increase/(decrease)		Primary factors explaining change
Cash and cash equivalents, beginning of period	89		314		(225	)
Provided by (used in):
Operating activities	82		425		(343	)	Lower cash flow from operations before changes in working capital ($140 million) mainly due to the 2018 one time receipt of $157 million for the termination of the Sundance Units B and C PPAs. There was also an unfavourable change in non-cash working capital ($203 million).
Investing activities	(53	)	(53	)	—		Higher note receivable related to Pioneer Pipeline project development costs ($50 million), higher additions to PP&E ($11 million) and lower receipts from finance leases ($9 million) were offset by the decrease in restricted cash related to the OCP debt ($35 million) and favourable change in non-cash investing working capital balances ($34 million)
Financing activities	(9	)	(357	)	348		Lower repayments of long-term debt ($631 million), lower dividends paid on preferred shares ($10 million) and lower distributions paid to subsidiaries' non-controlling interests ($9 million) partially offset by lower borrowings under credit facilities ($255 million) and lower realized gains on financial instruments ($50 million)
Translation of foreign currency cash	—		—		—
Cash and cash equivalents, end of period	109		329		(220	)

Other Consolidated Analysis

Unconsolidated Structured Entities or Arrangements

Disclosure is required of all unconsolidated structured entities or arrangements such as transactions, agreements, or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities, or variable interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. We currently have no such unconsolidated structured entities or arrangements.

Guarantee Contracts

We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, construction projects, and purchase obligations. At March 31, 2019, we provided letters of credit totaling $697 million (Dec. 31, 2018 - $720 million) and cash collateral of $182 million (Dec. 31, 2018 - $105 million). These letters of credit and cash collateral secure certain amounts included on our Condensed Consolidated Statements of Financial Position under risk management liabilities and decommissioning and other provisions.

Contingencies

I. Line Loss Rule Proceeding 

The Corporation has been participating in a line loss rule proceeding before the Alberta Utilities Commission ("AUC"). The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the Alberta Electric System Operator to, among other things, perform such retroactive calculations. The various decisions by the AUC are, however, subject to appeal and challenge.  A recent decision by the AUC determined the methodology to be used retroactively and it is now possible to estimate the total potential retroactive exposure faced by the Corporation for its non-PPA MWs.  The current estimate of exposure based on known data is $15 million and therefore the Corporation has recorded a provision of $15 million as at March 31, 2019 and Dec. 31, 2018. 

II. FMG Disputes

The Corporation is currently engaged in two disputes with Fortescue Metals Group Ltd. ("FMG").  The first arose as a result of FMG’s purported termination of the South Hedland PPA.  TransAlta has sued FMG, seeking payment of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force.  FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated. 

TRANSALTA CORPORATION M23

The second matter involves FMG’s claims against TransAlta related to the transfer of the Solomon Power Station to FMG.  FMG claims certain amounts related to the condition of the facility while TransAlta claims certain outstanding costs that should be reimbursed.

III. Balancing Pool Dispute

Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March 29, 2018 as part of the net book value payment required on termination of the Sundance B and C PPAs. The Balancing Pool, however, excluded certain mining and corporate assets that the Corporation believes should be included in the net book value calculation, which amounts to an additional $56 million. The dispute is currently proceeding through arbitration.

IV. Mangrove

On April 23, 2019, Mangrove Partners commenced an action in the Ontario Superior Court of Justice, naming TransAlta Corporation, each incumbent member of the Board of Directors of TransAlta Corporation, and Brookfield BRP Holdings (Canada) as defendants.  Mangrove Partners is seeking various remedies but primarily to set aside the Brookfield transaction. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations.

Financial Instruments

Refer to Note 14 of the notes to the audited annual consolidated financial statements within our 2018 Annual Integrated Report and Note 9 of our unaudited interim condensed consolidated financial statements as at and for the three months ended March 31, 2019 for details on Financial Instruments. Refer to the Governance and Risk Management section of our 2018 Annual Integrated Report and Note 10 of our unaudited interim condensed consolidated financial statements for further details on our risks and how we manage them. Our risk management profile and practices have not changed materially from Dec. 31, 2018.

We may enter into commodity transactions involving non-standard features for which observable market data is not available. These are defined under IFRS as Level III financial instruments. Level III financial instruments are not traded in an active market and fair value is, therefore, developed using valuation models based upon internally developed assumptions or inputs. Our Level III fair values are determined using data such as unit availability, transmission congestion, or demand profiles. Fair values are validated on a quarterly basis by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the financial statements.

As at March 31, 2019, total Level III financial instruments had a net asset carrying value of $656 million (Dec. 31, 2018 - $695 million net asset). The decrease during the period is primarily due to the settlement of contracts, unfavourable foreign exchange rates, and market price changes in value of the long-term power sale contract designated as an all-in-one cash flow hedge for which changes in fair value are recognized in other comprehensive income, partially offset by new contracts entered into during the period.

2019 Financial Outlook

 The following table outlines our expectation on key financial targets for 2019:

Measure	Target
Comparable EBITDA	$875 million to $975 million
FCF	$270 million to $330 million
Dividend	$0.16 per share annualized, 14 to 17 per cent payout of FCF
Range of Key Assumptions
Market	Power Prices ($/MWh)
Alberta Spot	$50 to $60
Alberta Contracted	$50 to $55
Mid-C Spot (US$)	$20 to $25
Mid-C Contracted (US$)	$47 to $53
Other assumptions relevant to 2019 financial outlook
Sustaining capital	$140 million to $165 million (revised)(1)
Productivity capital	$10 million to $15 million
Sundance coal capacity factor	30%
Hydro/ Wind resource	Long term average

(1) The original 2019 outlook for sustaining capital spend included an additional $20 million to $25 million in expected spend on finance leases. On implementation of IFRS 16, we reclassified payments on finance leases out of sustaining capital and now show this spend as a separate line to calculate FCF and segmented cash flow. See the Accounting Changes section of this MD&A for further details.

TRANSALTA CORPORATION M24

Operations

Availability

Availability of our Canadian coal fleet is expected to be in the range of 87 to 89 per cent in 2019. Availability of our other generating assets (gas, renewables) is expected to be in the range of 90 to 96 per cent in 2019. We will be accelerating our transition to gas and renewables generation, and continue on our coal-to-gas conversion strategy as set out in the Strategic Growth and Corporate Transformation section of this MD&A.

Market Pricing and Hedging Strategy

For 2019, power prices in Alberta are expected to be slightly higher than 2018 due to a full year with improved supply demand balances and strong settled prices in the first quarter of 2019 due to a very cold February. Pacific Northwest power prices for 2019 are expected to be lower than 2018. While prices in the first quarter of 2019 were strong due to natural gas prices and very cold weather, we don't anticipate the natural gas supply issues that impacted regional power prices in November and December to be repeated. Ontario power prices are expected to remain consistent with 2018 prices.

The objective of our portfolio management strategy is to deliver a high confidence for annual FCF which also provides for positive exposure to price volatility in Alberta. Given our cash operating costs, we can be more or less hedged in a given period, and we expect to realize our annual FCF targets through a combination of forward hedging and selling generation into the spot market.

Fuel Costs

In Alberta, we expect our cash fuel costs per tonne of coal to remain consistent with 2018 costs, even though we expect to mine approximately 2 - 3 million tonnes less in 2019. Total fuel costs on a dollar per MWh basis are expected to remain consistent with 2018 while total fuel costs are expected to be slightly lower due to increased co-firing with natural gas among the merchant units.

In the Pacific Northwest, our US Coal mine, adjacent to our power plant, is in the reclamation stage. Fuel at US Coal has been purchased primarily from external suppliers in the Powder River Basin and delivered by rail. The delivered fuel cost for the remainder of 2019 is expected to increase by approximately 3 per cent compared to costs incurred in 2018 mainly due to higher gas prices.

Most of our generation from gas is sold under contracts with pass-through provisions for fuel. For gas generation with no pass-through provision, we purchase natural gas from outside companies coincident with production, thereby minimizing our risk to changes in prices.

We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.

Energy Marketing

Comparable EBITDA from our Energy Marketing segment is affected by prices and volatility in the market, overall strategies adopted, and changes in regulation and legislation. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2019 objective for Energy Marketing is for the segment to contribute between $75 million to $85 million in gross margin for the year.

Exposure to Fluctuations in Foreign Currencies

Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the US dollar and Australian dollar by offsetting foreign-denominated assets with foreign-denominated liabilities and by entering into foreign exchange contracts.  We also have foreign-denominated expenses, including interest charges, which largely offset our net foreign-denominated revenues.

Net Interest Expense

Net interest expense for 2019 is expected to be lower than in 2018 largely due to lower interest rates, even when including the new Brookfield debt. However, changes in interest rates and in the value of the Canadian dollar relative to the US dollar can affect the amount of net interest expense incurred. In addition, interest expense will increase as a result of implementing IFRS 16. See the Accounting Changes section of this MD&A for further details.

Liquidity and Capital Resources

We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to approximately$0.9 billion under our committed facilities and $109 million in cash and cash equivalents. Our continued focus will be toward repositioning our capital structure and we expect to be well positioned to address the upcoming debt maturities in 2020 and 2022 with cash flow from operations, the proceeds received from the Brookfield investment and our existing credit facilities.

TRANSALTA CORPORATION M25

Growth and Coal-to-Gas Conversion Expenditures

Our growth projects are focused on sustaining our current operations and supporting our growth strategy in our renewables platform. A summary of the significant growth and major projects that are in progress is outlined below:

	Total project		Remaining estimated spend in 2019	Target completion date
	Estimated spend	Spent to date(1)			Details
Project
Big Level wind development project(2)	227	116	111	Q3 2019	90 MW wind project with a 15-year PPA
Antrim wind development project(3)	97	66	31	Q3 2019	29 MW wind project with two 20-year PPAs
Pioneer gas pipeline partnership	100	65	35	Q2 2019	50 per cent ownership in the 120 km natural gas pipeline to supply gas to Sundance and Keephills
Windrise wind development project	270	4	46	Q2 2021	207 MW wind project with a 20-year Renewable Electricity Support Agreement with AESO
Coal-to-gas conversions(4)	200	—	35	2020 to 2022	Coal-to-gas conversions at Canadian Coal
Total	894	251	258

(1) Represents amounts spent as of March 31, 2019.

(2) The numbers reflected above are in CAD but the actual cash spend on this project is in USD and therefore these amounts will fluctuate with changes in foreign exchange rates. The estimated total spend is USD$175 million, spent to date is USD$87 million and estimated total spend in 2019 is USD$88 million. TransAlta Renewables will fund the construction costs using its existing liquidity and tax equity.

(3) The numbers reflected above are in CAD but the actual cash spend on this project is in USD and therefore these amounts will fluctuate with changes in foreign exchange rates. The estimated total spend is USD$75 million, spent to date is USD$50 million and expected total spend in 2019 is USD$25 million. TransAlta Renewables will fund the acquisition and construction costs using its existing liquidity and tax equity.

(4) Does not include repowering opportunities.

Sustaining and Productivity Capital Expenditures

A significant portion of our sustaining and productivity capital is planned major maintenance, which includes inspection, repair and maintenance of existing components, and the replacement of existing components. Planned major maintenance costs are capitalized as part of PP&E and are amortized on a straight-line basis over the term until the next major maintenance event. It excludes amounts for day-to-day routine maintenance, unplanned maintenance activities, and minor inspections and overhauls, which are expensed as incurred.

Our estimate for total sustaining and productivity capital is allocated among the following:

Category	Description	Spent to date(1)	Expected spend in 2019
Routine capital	Capital required to maintain our existing generating capacity	12	50	—	60
Planned major maintenance	Regularly scheduled major maintenance	8	70	—	80
Mine capital	Capital related to mining equipment and land purchases	5	20	—	25
Total sustaining capital(2)		25	140	—	165
Productivity capital	Projects to improve power production efficiency and corporate improvement initiatives	2	10	—	15
Total sustaining and productivity capital		27	150	—	180

(1) As at March 31, 2019.

(2) The original 2019 outlook for sustaining capital spend included an additional $20 million to $25 million in expected spend on finance leases. On implementation of IFRS 16, we reclassified payments on finance leases out of sustaining capital and now show this spend as a separate line to calculate FCF and segmented cash flow. See the Accounting Changes section of this MD&A for further details.

Significant planned major outages at TransAlta's operated units for the remainder of 2019 include the following:

▪ two outages for major maintenance at Keephills Unit 1 and Sundance Unit 4 within our Canadian Coal segment that were started in the first quarter of 2019 and will be completed in the second quarter of 2019;

▪ one major outage in our Canadian Gas segment related to our Sarnia facility during the second quarter of 2019;

▪ distributed planned maintenance expenditures across the entire Hydro fleet; and

▪ distributed expenditures across our Wind fleet, focusing on planned component replacements.

Lost production as a result of planned major maintenance, excluding planned major maintenance for US Coal, which is scheduled during a period of dispatch optimization, is estimated as follows for 2019:

	Canadian Coal	Gas and Renewables	Total	Lost to date(1)
GWh lost	500 - 550	400 - 450	900 - 1,000	39

(1) As at March 31, 2019.

M26TRANSALTA CORPORATION

Funding of Capital Expenditures

Funding for these planned capital expenditures is expected to be provided by cash flow from operating activities, the proceeds received from the Brookfield investment and existing liquidity. We have access to approximately $1.0 billion in liquidity. The funds required for committed growth, sustaining capital, and productivity projects are not expected to be significantly impacted by the current economic environment.

Accounting Changes

A. Current Accounting Changes

The Corporation has adopted IFRS 16 Leases ("IFRS 16") with an initial adoption date of Jan. 1, 2019. IFRS 16 sets out the principles for the recognition, measurement, presentation and disclosure of leases. The standard provides a single lessee accounting model, requiring lessees to recognize a right of use asset and liabilities for all in-scope leases. Previously, the Corporation determined at contract inception whether an arrangement is or contains a lease under IAS 17 Leases (IAS 17) or International Financial Reporting Interpretations Committee interpretation 4 Determining whether an arrangement contains a lease. As a result of the IFRS 16 adoption, the Corporation has changed its accounting policy for leases, which is outlined in Note 2 of the Corporation's unaudited interim condensed consolidated financial statements.

The Corporation has elected to adopt IFRS 16 using the modified retrospective approach on transition. Comparative information has not been restated and is reported under IAS 17. Refer to the Corporation's most recent annual consolidated financial statements for information on its prior accounting policy. 

The Corporation recognized the cumulative impact of the initial application of the standard of $3 million in Deficit as at Jan. 1, 2019. In applying IFRS 16 for the first time, the Corporation has used the following practical expedients permitted by the standard:

▪ Exemption to not recognize right of use assets and lease liabilities for short-term leases that have a remaining lease term of less than 12 months as at Jan. 1, 2019 and for low value leases;

▪ Excluding initial direct costs for the measurement of the right of use asset at the date of initial application;

▪ Using hindsight in determining the lease term where the contract contains options to extend or terminate the lease;

▪ Adjusting the right of use assets by the amount of IAS 37 onerous contract provision immediately before the date of initial application; and

▪ Measuring the right of use asset at an amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognized in the statement of financial position immediately before the date of initial application.

Impact on the financial statements

Lessee

The Corporation recognized the cumulative impact of the initial application of the standard recording a right of use asset based on the corresponding lease liability measured at the present value of the remaining lease payments discounted using the Corporation's incremental borrowing rate (or the rate implicit in the lease) applied to the lease liabilities at Jan. 1, 2019. We recognized lease liabilities of $83 million as at Jan. 1, 2019, including $63 million that was previously included as finance lease liabilities.

The associated right of use assets were measured at an amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments, onerous contract provisions and lease inducements. On Jan. 1, 2019, the Corporation recognized right of use assets of $85 million, including $38 million that was previously included in property, plant and equipment, intangible assets and other assets.

Applying the IFRS 16 definition of a lease to a contractual arrangement that was accounted for as a finance lease under IAS 17 but is no longer considered a lease under IFRS 16, resulted in the derecognition of a finance lease asset of $29 million and a finance lease liability of $32 million with the net impact of $3 million recorded in Deficit.

Lessor

Several of the Corporation's long term contracts at certain wind, hydro and solar facilities are no longer considered to be operating leases under IFRS 16. Revenues earned on these are now accounted for applying IFRS 15 Revenue from Contracts with Customers. No significant change in the pattern of revenue recognition arose. The Corporation continues to account for its subleases as operating leases.

Refer to Note 2 of the Corporation's unaudited interim condensed consolidated financial statements for a more detailed discussion of the Corporation's adoption of IFRS 16.

TRANSALTA CORPORATION M27

Selected Quarterly Information

Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are usually incurred in the spring and fall when electricity prices are expected to be lower, as electricity prices generally increase in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Pacific Northwest, which impacts production at US Coal. Typically, hydro facilities generate most of their electricity and revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are historically greater during the cold winter months and lower in the warm summer months.

	Q2 2018		Q3 2018		Q4 2018		Q1 2019
Revenues	446		593		622		648
Comparable EBITDA(1)	248		250		261		221
FFO	188		204		217		169
Net earnings (loss) attributable to common shareholders	(105	)	(86	)	(122	)	(65	)
Net earnings (loss) per share attributable to common shareholders, basic and diluted(2)	(0.36	)	(0.30	)	(0.43	)	(0.23	)
	Q2 2017		Q3 2017		Q4 2017		Q1 2018
Revenues	503		588		638		588
Comparable EBITDA(1)	243		233		275		393
FFO	187		196		219		318
Net earnings (loss) attributable to common shareholders	(18	)	(27	)	(145	)	65
Net earnings (loss) per share attributable to common shareholders, basic and diluted(2)	(0.06	)	(0.09	)	(0.50	)	0.23

(1) During the first quarter of 2019, we revised our approach to reporting adjustments to arrive at comparable EBITDA, mainly to be more comparable with other companies in the industry. Comparable EBITDA is now adjusted to exclude the impact of unrealized mark-to-market gains or losses. Both the current and prior period amounts have been adjusted to reflect this change.

(2) Basic and diluted earnings per share attributable to common shares are calculated each period using the weighted average number of common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.

Reported net earnings, comparable EBITDA and FFO are generally higher in the first and fourth quarters due to higher demand associated with winter cold in the markets in which we operate and lower planned outages.

Net earnings attributable to common shareholders has also been impacted by the following variations and events:

▪ effects of impairment charges during the second, third and fourth quarters of 2018 and second quarter of 2017;

▪ recognition of the $157 million early termination payment received regarding Sundance B and C PPAs during the first quarter of 2018;

▪ a recovery of a writedown of deferred tax assets in the second quarter of 2017 and a writedown in the first quarter of 2019;

▪ change in income tax rates in the US in the fourth quarter of 2017;

▪ effects of changes in useful lives of certain Canadian Coal assets during the second and third quarters of 2017; and

▪ effects of an impairment of $137 million in the fourth quarter of 2017 on intercompany financial instruments that is attributable only to the non-controlling interests.

Disclosure Controls and Procedures

Management is responsible for establishing and maintaining adequate internal control over financial reporting (‘‘ICFR’’) and disclosure controls and procedures (“DC&P’’). There have been no material changes in our ICFR or DC&P during the three months ended March 31, 2019, that have materially affected, or are reasonably likely to materially affect, our ICFR or DC&P.

ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with IFRS. Management has used the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) in order to assess the effectiveness of the Corporation’s ICFR.

DC&P refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under securities legislation are recorded, processed, summarized and reported within the time frame specified in securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under securities legislation is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure.

Together, the ICFR and DC&P frameworks provide internal control over financial reporting and disclosure. In designing and evaluating our ICFR and DC&P, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and as such may not prevent or detect all misstatements, and management is required to apply its judgment in evaluating and implementing possible controls and procedures. Further, the

effectiveness of ICFR is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may change.

Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR and DC&P as of the end of the period covered by this report. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at March 31, 2019, the end of the period covered by this report, our ICFR and DC&P were effective.

Supplemental Information

		March 31, 2019		Dec. 31, 2018
Closing market price (TSX) ($)		9.82		5.59
Price range for the last 12 months (TSX) ($)	High	10.04		7.90
	Low	5.44		5.44
FFO before interest to adjusted interest coverage(2)(times)		5.1		4.8
Adjusted FFO to adjusted net debt(2)(%)		20.7		20.8
Adjusted net debt to comparable EBITDA(1, 2) (times)		3.7		3.7
Adjusted net debt to invested capital(1) (%)		50.8		49.7
Return on equity attributable to common shareholders(2)(%)		(25.0	)	(15.8	)
Return on capital employed(2)(%)		(1.9	)	0.7
Earnings coverage(2)(times)		(0.7	)	0.2
Dividend payout ratio based on FFO(1, 2)(%)		6.1		7.6
Dividend coverage(2)(times)		10.9		18.3
Dividend yield(2)(%)		1.6		2.9

(1) These ratios incorporate items that are not defined under IFRS. None of these measurements should be used in isolation or as a substitute for the Corporation’s reported financial performance or position as presented in accordance with IFRS. These ratios are useful complementary measurements for assessing the Corporation’s financial performance, efficiency, and liquidity and are common in the reports of other companies but may differ by definition and application. For a reconciliation of the non-IFRS measures used in these calculations, refer to the Discussion of Financial Results section of this MD&A.

(2) Last 12 months. During the first quarter of 2019, we revised comparable EBITDA to remove the unrealized mark-to-market gains (losses). 2018 results have been revised to reflect this change.

Ratio Formulas

FFO before interest to adjusted interest coverage = FFO + interest on debt and lease obligations - interest income - capitalized interest / interest on debt and lease obligations + 50 per cent dividends paid on preferred shares - interest income

Adjusted FFO to adjusted net debt = FFO - 50 per cent dividends paid on preferred shares / period end long-term debt and lease obligations including fair value (asset) liability of hedging instruments on debt + 50 per cent issued preferred shares - cash and cash equivalents

Adjusted net debt to comparable EBITDA = long-term debt and lease obligations including current portion and fair value (asset) liability of hedging instruments on debt + 50 per cent issued preferred shares - cash and cash equivalents / comparable EBITDA    

Adjusted net debt to invested capital = long-term debt and lease obligations including current portion and fair value (asset) liability of hedging instruments on debt + 50 per cent issued preferred shares - cash and cash equivalents / adjusted net debt + non-controlling interests + equity attributable to shareholders - 50 per cent issued preferred shares

Return on equity attributable to common shareholders = net earnings (loss) attributable to common shareholders / equity attributable to shareholders excluding AOCI - issued preferred shares

Return on capital employed = earnings (loss) before income taxes + net interest expense - net earnings (loss) attributable to non-controlling interests / invested capital excluding AOCI

Earnings coverage = net earnings (loss) attributable to shareholders + income taxes + net interest expense / interest on debt and lease obligations + 50 per cent dividends paid on preferred shares - interest income

Dividend payout ratio = dividends paid on common shares / FFO - 50 per cent dividends paid on preferred shares

Dividend coverage ratio based on comparable FFO = FFO - 50 per cent dividends paid on preferred shares/ dividends paid on common shares

Dividend yield = dividend paid per common share / current period’s closing market price

M28TRANSALTA CORPORATION

Glossary of Key Terms

Availability - A measure of the time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.

Capacity - The rated continuous load-carrying ability, expressed in megawatts, of generation equipment.

Force Majeure -Literally means “greater force”. These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.

Gigawatt - A measure of electric power equal to 1,000 megawatts.

Gigawatt Hour (GWh) - A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.

Greenhouse Gas (GHG) - Gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.

Megawatt (MW) - A measure of electric power equal to 1,000,000 watts.

Megawatt Hour (MWh) - A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.

Power Purchase Arrangement (PPA) - A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to buyers.

Unplanned Outage - The shut-down of a generating unit due to an unanticipated breakdown.

TRANSALTA CORPORATION M29

TransAlta Corporation

110 - 12th Avenue S.W.

Box 1900, Station “M”

Calgary, Alberta Canada T2P 2M1

Phone

403.267.7110

Website

www.transalta.com

AST Trust Company (Canada)

P.O. Box 700 Station “B”

Montreal, Québec Canada H3B 3K3

Phone Toll-free in North America: 1.800.387.0825

Toronto or outside North America: 416.682.3860

Fax 514.985.8843

E-mail

inquiries@canstockta.com

Website www.canstockta.com

FOR MORE INFORMATION

Media and Investor Inquiries

Investor Relations

Phone1.800.387.3598 in Canada and United States

or 403.267.2520

Fax

403.267.7405

E-mail

investor_relations@transalta.com

TRANSALTA CORPORATION M30